U.S. patent number 8,245,778 [Application Number 12/670,079] was granted by the patent office on 2012-08-21 for fluid control apparatus and methods for production and injection wells.
This patent grant is currently assigned to ExxonMobil Upstream Research Company. Invention is credited to Bruce A. Dale, Charles S. Yeh.
United States Patent |
8,245,778 |
Yeh , et al. |
August 21, 2012 |
Fluid control apparatus and methods for production and injection
wells
Abstract
Flow control systems and methods for use in injection wells and
in the production of hydrocarbons utilize a particulate material
disposed in an external flow area of a flow control chamber having
an internal flow channel and an external flow area separated at
least by a permeable region. The particulate material transitions
from a first accumulated condition to a free or released condition
when a triggering condition is satisfied without requiring user or
operator intervention. The released particles accumulate without
user or operator intervention, to control the flow of production
fluids through a flow control chamber by at least substantially
blocking the permeable region between the external flow area and
the internal flow channel.
Inventors: |
Yeh; Charles S. (Spring,
TX), Dale; Bruce A. (Sugar Land, TX) |
Assignee: |
ExxonMobil Upstream Research
Company (Houston, TX)
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Family
ID: |
40567720 |
Appl.
No.: |
12/670,079 |
Filed: |
August 7, 2008 |
PCT
Filed: |
August 07, 2008 |
PCT No.: |
PCT/US2008/072429 |
371(c)(1),(2),(4) Date: |
January 21, 2010 |
PCT
Pub. No.: |
WO2009/051881 |
PCT
Pub. Date: |
April 23, 2009 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20100200233 A1 |
Aug 12, 2010 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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60999106 |
Oct 16, 2007 |
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Current U.S.
Class: |
166/236;
166/276 |
Current CPC
Class: |
E21B
43/12 (20130101); E21B 43/32 (20130101); E21B
43/082 (20130101) |
Current International
Class: |
E21B
43/00 (20060101) |
Field of
Search: |
;166/236,276,278 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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WO 99/36667 |
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Jul 1999 |
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WO |
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WO 99/54592 |
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Oct 1999 |
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WO |
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WO 2004/094784 |
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Nov 2004 |
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WO |
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WO 2005/061850 |
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Jul 2005 |
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WO |
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WO 2007/024627 |
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Mar 2007 |
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WO |
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WO 2007/092083 |
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Aug 2007 |
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WO |
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WO 2007/094897 |
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Aug 2007 |
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WO |
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Other References
Bennett, C., et al., "Design Methodolgy for Selection of Horizontal
Open-Hole Sand Control Completions Supported by Field Case
Histories", SPE 65140, Oct. 24-25, 2000, pp. 1-19, 2000 SPE
European Petroleum Conf., Paris, France. cited by other .
Kaiser, T.M.V., et al., "Inflow Analysis and Optimization of
Slotted Liners", SPE 80145, Nov. 6-8, 2000, pp. 200-209,
SPE/Petroleum Society of CIM Int'l. Conf. on Horizontal Well
Technology, Calgary, Canada. cited by other .
Penberthy, Jr., W.L., et al., "Sand Control, Chpt. 4--Gravel-Pack
Design", 1992, 8 pages, Henry L. Doherty Memorial Fund of AIME
Society of Petroleum Engineers, Richardson, TX. cited by other
.
Seright, R.S., et al., "A Strategy for Attacking Excess Water
Production", SPE 84966, May 15-16, 2001, pp. 158-169, 2001 SPE
Permian Basil Oil and Gas Recovery Conf., Midland, TX. cited by
other .
Tang, Y., et al., "Performance of Horizontal Wells Completed with
Slotted Liners and Perforations", SPE 65516, Nov. 6-8, 2000, pp.
1-15, 2000 SPE/Petroleum Society of CIM Int'l. Conf. on Horizontal
Well Technology, Calgary, Canada. cited by other .
Tiffin, D.L., et al., "New Criteria for Gravel and Screen Selection
for Sand Control", SPE 39437, Feb. 18-19, 1998, pp. 201-214, 1998
SPE Formation Damage Control Conf., Lafayette, LA. cited by other
.
Wong, G.K., et al., "Design, Execution, and Evaluation of Frac and
Pack (F&P) Treatments in Unconsolidated Sand Formations in the
Gulf of Mexico", SPE 26563, Oct. 3-6, 1983, pp. 491-506, 68.sup.th
Annual Technical Conf. & Exh. of the Society of Petroleum
Engineers, Houston, TX. cited by other .
International Search Report, dated Nov. 12, 2008,
PCT/US2008/072429. cited by other.
|
Primary Examiner: Neuder; William P
Assistant Examiner: Wallace; Kipp
Attorney, Agent or Firm: ExxonMobil Upstream Research
Company--Law Department
Parent Case Text
CROSS REFERENCE TO RELATED APPLICATIONS
This application is the National Stage entry under 35 U.S.C. 371 of
PCT/US2008/072429, that published as WO 2009/051881 and was filed 7
Aug. 2008, which claims the benefit of U.S. Provisional Application
No. 60/999,106, filed 16 Oct. 2007, each of which is incorporated
herein by reference, in its entirety, for all purposes.
Claims
What is claimed is:
1. A system for use with production of hydrocarbons, the system
comprising: a first tubular member defining an internal flow
channel and at least partially defining an external flow area, and
wherein the first tubular member comprises a permeable region
providing fluid communication between the external flow area and
the internal flow channel; and a particulate composition disposed
in the external flow area, wherein the particulate composition
comprises a plurality of particles bound by a reactive binding
material adapted to release particles in response to a triggering
condition wherein the particulate composition is fixedly disposed
in the external flow area until particles are released by the
binding materials, and wherein particles released from the
particulate composition move within the external flow area and are
at least substantially retained in the external flow area to form a
particulate accumulation at least substantially blocking the
permeable region of the first tubular member.
2. The system of claim 1, wherein the particulate composition
comprises a plurality of particles of varied dimensions.
3. The system of claim 1, wherein the binding material maintains
its integrity when contacted by product fluids and releases
particles when contacted by triggering fluids.
4. The system of claim 1, wherein the reactive binding material
includes at least one composition selected from potassium silicate
and urea; potassium silicate and formamide; and ethylpolysilicate,
hydrochloric acid, and ethanol.
5. The system of claim 1, wherein the triggering condition includes
the presence of one or more aqueous fluids.
6. The system of claim 1, further comprising at least one chamber
isolator disposed in the external flow area adapted to at least
partially block flow of particles in the external flow area to
initiate particulate accumulation.
7. The system of claim 1, wherein at least two particulate
compositions are disposed in the external flow area, and wherein
the at least two particulate compositions are adapted to
cooperatively provide staged deployment of the particles and staged
blockage of the external flow area.
8. A system for use with production of hydrocarbons, the system
comprising: a first tubular member defining an internal flow
channel, wherein the tubular member comprises a permeable region
providing fluid communication with the internal flow channel; an
exterior member having an internal surface radially spaced from an
outer surface of the first tubular member, wherein the first
tubular member and the exterior member at least partially define an
external flow area, wherein the exterior member comprises a
permeable region, wherein the permeable region of the exterior
member provides an inlet to the external flow area creating a flow
path between the inlet of the exterior member and the permeable
region of the first tubular member; and a particulate composition
disposed in the external flow area at least partially in the flow
path, wherein the particulate composition comprises a plurality of
particles bound by a reactive binding material adapted to release
particles in response to a triggering condition, and wherein at
least some of the released particles accumulate to form a
particulate accumulation at least substantially blocking the
permeable region of the first tubular member.
9. The system of claim 8, wherein at least one of the permeable
region of the first tubular member, the permeable region of the
exterior member, and their combination is adapted to prevent
formation particles from entering the internal flow channel.
10. The system of claim 8, wherein the particles of the particulate
composition are selected from at least one of gravel, sand,
carbonate, silt, clay, or man-made particles.
11. The system of claim 8, wherein the binding material maintains
its integrity when contacted by product fluids and releases
particles when contacted by triggering fluids.
12. The system of claim 8, wherein the reactive binding material is
selected to control the rate of particle release from the
particulate composition.
13. The system of claim 8, wherein the released particles are
adapted to flow within the external flow area toward the permeable
region of the first tubular member and are dimensioned to be at
least substantially retained in the external flow area by the
permeable region of the first tubular member forming the
particulate accumulation at least substantially blocking the
permeable region of the first tubular member.
14. The system of claim 8, wherein the particulate composition
comprises particles having a variety of dimensions.
15. The system of claim 14, wherein the particles of the
particulate composition have dimensions ranging from at least about
0.0001 mm to less than about 100 mm.
16. The system of claim 14, wherein the permeable region of the
first tubular member has a predetermined opening size, and wherein
greater than about 10% of the particles of the particulate
composition are larger than the predetermined opening size of the
first tubular member.
17. The system of claim 8, wherein the particles of the particulate
composition comprise materials selected to provide a reversible
particulate accumulation.
18. The system of claim 8, further comprising at least one chamber
isolator disposed in the external flow area adapted to at least
partially block flow of particles in the external flow area to
initiate particulate accumulation.
19. A system for use in production of hydrocarbons, the system
comprising: a production string including a base pipe having an
internal flow channel adapted to receive fluids when in a wellbore
environment in a formation; at least one changed-path flow chamber
defined in the production string and associated with the base pipe,
wherein each changed-path flow chamber comprises offset inner and
outer permeable regions configured to define a flow path between
the outer permeable region and the inner permeable region, wherein
the inner permeable region provides fluid communication between the
changed-path flow chamber and the internal flow channel, and
wherein the outer permeable region provides fluid communication
between the wellbore environment and the changed-path flow chamber;
a consolidated particulate pack disposed at least partially in the
flow path between the inner and the outer permeable regions;
wherein the consolidated particulate pack comprises a plurality of
particles consolidated together by a binding agent selected to
release particles in response to a triggering condition; and
wherein the particles released from the consolidated particulate
pack are dimensioned to be at least substantially retained by the
inner permeable region such that the particles accumulate adjacent
to the inner permeable region to at least substantially block the
inner permeable region limiting the fluid communication between the
changed-path flow chamber and the internal flow channel.
20. The system of claim 19, wherein the particles of the
consolidated particulate pack are selected from at least one of
gravel, sand, carbonate, silt, clay, or man-made particles.
21. The system of claim 19, wherein the binding agent maintains its
integrity when contacted by product fluids and releases particles
when contacted by triggering fluids.
22. The system of claim 19, wherein the binding agent is selected
to control the rate of particle release from the consolidated
particulate pack.
23. The system of claim 19, wherein the inner permeable region has
a predetermined opening size, and wherein greater than about 10% of
the particles of the particulate pack are larger than the
predetermined opening size of the inner permeable region.
24. A method associated with the production of hydrocarbons, the
method comprising: providing a production/injection string
including a base pipe having an internal flow channel adapted to
receive fluids when in a wellbore environment in a formation;
defining at least one external flow area separated from the
internal flow channel by an inner permeable region; providing a
consolidated particulate pack comprising a plurality of particles
consolidated together by a binding agent selected to release
particles in response to a triggering condition, wherein the
released particles of the consolidated particulate pack are
dimensioned to accumulate in the external flow area and to at least
substantially block fluids from entering the internal flow channel;
and fixedly disposing the consolidated particulate pack in the
external flow area until the particles are released by the binding
materials.
25. The method of claim 24, wherein defining at least one external
flow area includes providing an outer jacket spaced away from the
base pipe of the production/injection string and includes defining
at least one flow control chamber including at least one inlet to
the external flow area.
26. The method of claim 25, wherein the inlet to the external flow
area is offset from the inner permeable region of the base
pipe.
27. The method of claim 24 further comprising: disposing the
production/injection string in a well; and operating the well in
association with the production of hydrocarbons, wherein the
production string operates in a first configuration until the
triggering condition is satisfied and the particles are released,
and wherein the production string operates in a second
configuration following the accumulation of the released
particles.
28. The method of claim 27, wherein the well is operated as a
production well.
29. The method of claim 27, further comprising reversing the
particulate accumulation blockage in the external flow area.
30. The method of claim 27 further comprising producing
hydrocarbons from the well.
Description
FIELD
This invention relates generally to apparatus and methods for use
in wellbores. More particularly, this invention relates to wellbore
apparatus and methods for producing hydrocarbons and managing water
production.
BACKGROUND
This section is intended to introduce the reader to various aspects
of art, which may be associated with embodiments of the present
invention. This discussion is believed to be helpful in providing
the reader with information to facilitate a better understanding of
particular techniques of the present invention. Accordingly, it
should be understood that these statements are to be read in this
light, and not necessarily as admissions of prior art.
The production of hydrocarbons, such as oil and gas, has been
performed for numerous years. To produce these hydrocarbons, a
production system may utilize various devices for specific tasks
within a well. Typically, these devices are placed into a wellbore
completed in either cased-hole or open-hole completion. In
cased-hole completions, wellbore casing is placed in the wellbore
and perforations are made through the casing into subterranean
formations to provide a flow path for formation fluids, such as
hydrocarbons, into the wellbore. Alternatively, in open-hole
completions, a production string is positioned inside the wellbore
without wellbore casing. The formation fluids flow through the
annulus between the subsurface formation and the production string
to enter the production string.
When producing hydrocarbons from subterranean formations,
especially poorly consolidated formations or formations weakened by
increasing downhole stress due to wellbore excavation and/or fluids
withdrawal, it is possible to produce undesirable materials, such
as solid materials (for example, sand) and fluids other than the
desired hydrocarbons (for example, water). In some cases,
formations may produce hydrocarbons without sand until the onset of
water production from the formations. With the onset of water,
these formations collapse or fail due to increased drag forces
(water generally has higher viscosity than oil or gas) and/or
dissolution of material holding sand grains together. Additionally
or alternatively, water is often produced with hydrocarbon due to
various causes including coning (rise of near-well
hydrocarbon-water contact), casing leaks, poor cementing, high
permeability streaks, natural fractures, and fingering from
injection wells.
The sand/solids and water production can result in a number of
problems. These problems include productivity loss, equipment
damage, and/or increased treating, handling and disposal costs. For
example, the sand/solids production may plug or restrict flow paths
resulting in reduced productivity. The sand/solids production may
also cause severe erosion resulting in damage to wellbore
equipment, which may create well control problems. When produced to
the surface, the sand is removed from the flow stream and has to be
disposed of properly, which increases the operating costs of the
well.
Water production also reduces productivity. For instance, because
water is heavier than hydrocarbon fluids, it takes more pressure to
move it up and out of the well. That is, the more water produced,
the less pressure available to move the hydrocarbons, such as oil.
In addition, water is corrosive and may cause severe equipment
damage if not properly treated. Similar to the sand, the water also
has to be removed from the flow stream and disposed of properly.
Any one or more of these consequences of water production increases
the cost of operating the well.
The sand/solids and water production may be further compounded with
wells that have a number of different completion intervals in which
the formation strength may vary from interval to interval. Because
the evaluation of formation strength is complicated, the ability to
predict the timing of the onset of sand and/or water is limited. In
many situations reservoirs are commingled to minimize investment
risk and maximize economic benefit. In particular, wells having
different intervals and marginal reserves may be commingled to
reduce economic risk. One of the risks in these applications is
that sand failure and/or water breakthrough in any one of the
intervals threatens the remaining reserves in the other intervals
of the completion.
Conventional methods for preventing or mitigating water production
include selective perforation, zone isolation, inflow control
system, resin treatment, downhole separation, and
surface-controlled downhole valves. Preventive methods such as
selective perforation, zone isolation, inflow control systems, and
surface-controlled downhole valves are applied at pre-determined,
high water production potential locations along the wellbore (or
low potential in the case of selective perforation). Due to the
uncertainty in identifying the timing, location and magnitude of
potential water production, the results have been often
unsatisfactory.
The historical water shut-off method is injecting chemicals into
the water production intervals to plug the formation matrix. The
chemicals include cement and resins, which are gelled or solidified
with temperature and time. These methods have long been challenged
by gelation kinetics, placement, and long-term stability. Other
common methods include the use of packer or cement plugs to isolate
water production zones. Mechanical sleeve or casing cladding has
also been used to isolate the water inflow. The technique involves
positioning either a thermally inflatable patch or a mechanically
expandable patch against the desired cladding length. Good
planning, design, and execution are required for job success.
Downhole separation methods rely upon the installation of a
hydrocyclone and pump in the borehole to inject separated water to
different subterranean horizons. The increasing completion
complexity can be readily appreciated. To further complicate these
efforts, the sizing of a suitable separator is difficult due to the
changing incoming water rate during the well lifetime.
In recent efforts to address the problems presented by water
production, polymers have been used to modify the permeability of
the tubes and pipes associated with the production string. For
example, some efforts include injecting polymers from the surface
to target areas of water production and impede the water flow. The
injected polymers have to be carefully selected and carefully
injected for any chance of success in this implementation.
Processes such as this requiring on-site intervention are generally
more economically and technologically challenging.
As a variation on the efforts to use polymers to address water
production, others have attempted to coat screens, such as
conventional sand screens, with swellable materials designed to
seal flow paths through swelling. These swellable materials are
conventionally a polymeric material or other material coated with a
polymer that reacts upon contact with water to swell. Past efforts
have attempted to design screens having sufficient spacing to allow
fluid flow under desired conditions and to form an adequate seal
under undesired conditions. For example, the selection of the
swellable materials and the choice of how much swellable material
to incorporate in the screen required careful design to ensure the
polymer or other material would react when desired and in the
manner intended. Other efforts have disposed fixed swelling members
in association with a conventional sand screen attempting to cause
the swelling members to swell around the sand screen when water is
produced. However, here again, the efforts have relied upon costly
swellable materials that require careful selection. For example,
when polymeric swelling materials are used, care must be taken to
ensure that the polymer does not react with other chemicals that
may be in the produced fluids, either to swell or in some other
manner.
While typical sand and water control, remote control technologies,
and interventions may be utilized, these approaches often drive the
cost for marginal reserves beyond the economic limit. As such, a
simple, lower cost alternative may be beneficial to lower the
economic threshold for marginal reserves and to improve the
economic return for certain larger reserve applications.
Accordingly, the need exists for a well completion apparatus that
provides a mechanism for managing the production of water within a
wellbore, while staying within dimensional limitations of a
wellbore.
Other related material may be found in at least U.S. Pat. No.
6,913,081; U.S. Pat. No. 6,767,869; U.S. Pat. No. 6,672,385; U.S.
Pat. No. 6,660,694; U.S. Pat. No. 6,516,885; U.S. Pat. No.
6,109,350; U.S. Pat. No. 5,435,389; U.S. Pat. No. 5,209,296; U.S.
Pat. No. 5,222,556; U.S. Pat. No. 5,222,557; U.S. Pat. No.
5,211,235; U.S. Pat. No. 5,101,901; and U.S. Patent Application
Publication No. 2004/0177957. Additional related material may be
found in U.S. Pat. No. 5,722,490; U.S. Pat. No. 6,125,932; U.S.
Pat. No. 4,064,938; U.S. Pat. No. 5,355,949; U.S. Pat. No.
5,896,928; U.S. Pat. No. 6,622,794; U.S. Pat. No. 6,619,397;
International Patent Publication WO/2007/094897; and International
Patent Application No. PCT/US2004/01599. Further, additional
information may also be found in Penberthy & Shaughnessy, SPE
Monograph Series--"Sand Control", ISBN 1-55563-041-3 (2002);
Bennett et al., "Design Methodology for Selection of Horizontal
Open-Hole Sand Control Completions Supported by Field Case
Histories," SPE 65140 (2000); Tiffin et al., "New Criteria for
Gravel and Screen Selection for Sand Control," SPE 39437 (1998);
Wong G. K. et al., "Design, Execution, and Evaluation of Frac and
Pack (F&P) Treatments in Unconsolidated Sand Formations in the
Gulf of Mexico," SPE 26563 (1993); T. M. V. Kaiser et al., "Inflow
Analysis and Optimization of Slotted Liners," SPE 80145 (2002);
Yula Tang et al., "Performance of Horizontal Wells Completed with
Slotted Liners and Perforations," SPE 65516 (2000); and Graves, W.
G., et. Al., "World Oil Mature Oil & Gas Wells Downhole
Remediation Handbook," Gulf Publishing Company (2004).
SUMMARY
In some implementations of the present invention, systems for use
with production of hydrocarbons include a first tubular member
defining an internal flow channel. The first tubular member also at
least partially defines an external flow area. The first tubular
member further comprises a permeable region providing fluid
communication between the external flow area and the internal flow
channel. A particulate composition is disposed in the external flow
area and comprises a plurality of particles bound by a reactive
binding material. The binding material is adapted to release
particles in response to a triggering condition, such as the
presence of water in the production fluids. Once released, the
particles move within the external flow area and are at least
substantially retained in the external flow area to form a
particulate accumulation. The particulate accumulation forms in the
external flow area to block the permeable region of the first
tubular member.
In some implementations, the present systems include a first
tubular member and an exterior member that cooperate to at least
partially define an external flow area. The first tubular member
also defines an internal flow channel and comprises a permeable
region providing fluid communication with the internal flow
channel. The exterior member also comprises a permeable region. The
permeable region of the exterior member provides an inlet to the
external flow area creating a flow path between the inlet of the
exterior member and the permeable region of the first tubular
member. A particulate composition is disposed in the external flow
area at least partially in the flow path. The particulate
composition comprises a plurality of particles bound by a reactive
binding material adapted to release particles in response to a
triggering condition. After being released from the particulate
composition, at least some of the released particles accumulate to
form a particulate accumulation blocking the permeable region of
the first tubular member.
Systems within the scope of the present invention may also be
described as including a production string and at least one flow
control chamber. The production string includes a production tube
having an internal flow channel adapted to receive fluids when in a
wellbore environment in a formation. The at least one flow control
chamber is defined in the production string and may include a
changed-path flow control chamber. The changed-path flow control
chamber comprises offset inner and outer permeable regions
configured to define a flow path between the outer permeable region
and the inner permeable region. Flow control chambers that are not
changed-path flow control chambers also include inner and outer
permeable regions but the permeable regions are not offset. A
consolidated particulate pack is disposed at least partially in the
flow path between the inner and the outer permeable regions. The
consolidated particulate pack comprises a plurality of particles
held together by a binding agent. The binding agent is selected to
release particles in response to a triggering condition. The
particles released from the consolidated particulate pack are
dimensioned to be at least substantially retained by the inner
permeable region. The retained particles may accumulate adjacent to
the inner permeable region to block the inner permeable region
preventing fluids from entering the internal flow channel.
The present invention also includes methods for control flow of
production fluids from a wellbore. Exemplary methods include
providing a production string including a production tube having an
internal flow channel adapted to receive fluids when in a wellbore
environment. At least one external flow area is defined in
association with the production tube and is separated from the
internal flow channel by an inner permeable region. A consolidated
particulate pack comprising a plurality of particles is provided.
The particles of the particulate pack are held together by a
binding agent selected to release particles in response to a
triggering condition. The consolidated particulate pack is disposed
in the external flow area. The particles of the consolidated
particulate pack are dimensioned to accumulate adjacent to the
inner permeable region and to prevent fluids from entering the
internal flow channel.
BRIEF DESCRIPTION OF THE DRAWINGS
The foregoing and other advantages of the present technique may
become apparent upon reading the following detailed description and
upon reference to the drawings in which:
FIG. 1 is an exemplary production system in accordance with certain
aspects of the present disclosure;
FIGS. 2A-2C are schematic side views, including partial cutaway
views, of a water control system;
FIG. 3 is a schematic view of a portion of a water control
system;
FIGS. 4A-4C are schematic views of a portion of a water control
system;
FIGS. 5A-5F illustrate various views and components of a water
control system;
FIG. 6 is schematic side view of an assembled water control
system;
FIG. 7 is a schematic side view of water control systems disposed
within a producing wellbore;
FIG. 8 is a schematic side view of water control systems disposed
within a producing wellbore;
FIG. 9 is a schematic view of a portion of a water control
system;
FIGS. 10A and 10B are schematic views of portions of water control
systems;
FIG. 11 is a schematic view of a portion of a water control
system;
FIG. 12 is a schematic view of a portion of a water control
system;
FIG. 13 is a schematic view of a portion of a water control
system;
FIG. 14 is a flow chart representative of methods associated with
the present disclosure; and
FIG. 15 is a flow chart representative of methods associated with
the present disclosure.
DETAILED DESCRIPTION
In the following detailed description, specific aspects and
features of the present invention are described in connection with
several embodiments. However, to the extent that the following
description is specific to a particular embodiment or a particular
use of the present techniques, it is intended to be illustrative
only and merely provides a concise description of exemplary
embodiments. Moreover, in the event that a particular aspect or
feature is described in connection with a particular embodiment,
such aspects and features may be found and/or implemented with
other embodiments of the present invention where appropriate.
Accordingly, the invention is not limited to the specific
embodiments described below, but rather; the invention includes all
alternatives, modifications, and equivalents falling within the
scope of the appended claims.
The present disclosure relates to systems and methods to control
fluid flow through production tubes to enhance and/or facilitate
the production of hydrocarbons from producing wells. In accordance
with the present disclosure, a consolidated particulate pack is
combined with a flow control chamber to provide a fluid control
system capable of limiting or preventing the flow of undesired
fluids into the production tube without requiring monitoring or
intervention by operators. References herein to fluids to be
controlled by the present systems and methods include liquid and
gaseous fluids. The presence of water in the production fluid is
referred to frequently herein as a triggering condition. In such
references, the nomenclature water is intended to refer to aqueous
fluids generally and includes any production fluids in which water
is present. As discussed more fully below, the particulate packs of
the present disclosure may be configured to respond under different
triggering conditions, such as greater or lesser concentrations of
water in the production fluids.
While the present disclosure refers primarily to production strings
and production operations, the principles and teachings of the
present disclosure, and therefore the scope of the claims,
encompasses application of the present technologies to injection
wells and injection operations. In injection operations, for
example, certain injection profiles to the reservoir are desired
for efficient accomplishment of the injection objectives, such as
water flooding, matrix acidizing, etc. However, using water
flooding as an example, the injected water often takes the path of
least resistance through the formation after leaving the injection
string. Depending on the formation and the reservoir, the path of
least resistance may not coincide with the desired injection
profile. For example, the water from the water flood is typically
intended to flow through areas of low permeability to flood or push
the oil toward a producing well. However, if there are areas of
higher permeability, such as areas of naturally high permeability,
natural fractures, induced fractures, wormholes, etc., the water
will naturally flow in that direction, reducing the treatment
efficiency and possibly resulting in early water breakthrough in
the production wells. Similarly, injection operations for
stimulation, such as matrix acidizing, may have targeted areas for
the application of the acid and the acid may have natural affinity
for particular formation features, which may not always be the
same. Utilizing the technologies, systems, and methods described
herein, segments of the injection string may be selectively closed,
or at least substantially blocked, to restrict the flow of fluids
through that segment. While the fluids may still contact the
formation adjacent the blocked segment, it only does so after
overcoming the friction in the annulus from the desired target zone
to the `thief zone.`
As will be seen in the discussion below, the systems and methods of
the present disclosure may be adapted to provide unrestricted flow
followed by a restricted flow after a triggering condition is met.
The triggering condition may be naturally occurring, such as water
production from the formation, or may be operator imposed. For
example, a triggering fluid may be strategically injected in an
injection operation to adjust the injection profile. Still further,
the restricted flow profile can be reversed in some
implementations. The reversal, whether in injection operations or
production operations, may utilize an injected fluid or a natural
produced fluid. While water is a fluid that may be used as a
triggering fluid, other fluids, including liquids and gases, may be
selected as the triggering fluid. The selection of particles for
the particulate pack, the selection of binding materials, and the
selection of triggering fluids may each be influenced by the
reservoir, the formation, and the planned operations. While the
description below refers primarily to water-based triggering fluids
and water control in production operations, the consolidated
particle packs may be used in a variety of configurations and
implementations.
The consolidated particulate pack is disposed in the flow control
chamber and is configured to release particles from the pack in
response to predetermined condition(s), such as contact with water
or other undesired fluid(s). For example, the consolidated
particulate pack may include binding agents selected to dissolve in
water (or under other conditions) to release the bound particles.
The released particles are then transported in flow paths in the
flow control chamber and accumulate in the flow control chamber in
a manner to hinder, limit, or at least substantially prevent fluid
flow through the flow control chamber. Implementation of the
present systems and methods may allow produced fluids to enter the
production tubing string in certain production intervals while
limiting such flow in other production intervals. For example, the
present systems and methods utilize compartments or chambers in the
production string, such as in tool sections or pipes connected to
production tubing, to create localized particulate accumulations
when water is produced.
Turning now to the drawings, and referring initially to FIG. 1, an
exemplary production system 100 in accordance with certain aspects
of the present techniques is illustrated. In the exemplary
production system 100, a floating production facility 102 is
coupled to a subsea tree 104 located on the sea floor 106. However,
it should be noted that the production system 100 is illustrated
for exemplary purposes and the present techniques may be useful in
the production or injection of fluids from any subsea, platform, or
land location. Accordingly, the production system may include a
floating production facility 102, as illustrated, or any other
suitable production facilities.
The floating production facility 102 is configured to monitor and
produce hydrocarbons from one or more subsurface formations, such
as subsurface formation 107, which may include multiple production
intervals or zones 108a-108n, wherein number "n" is any integer
number, having hydrocarbons, such as oil and gas. To access the
production intervals 108a-108n, the floating production facility
102 is coupled to a subsea tree 104 and control valve 110 via a
control umbilical 112. The control umbilical 112 may be operatively
connected to production tubing for providing hydrocarbons from the
subsea tree 104 to the floating production facility 102, control
tubing for hydraulic or electrical devices, and a control cable for
communicating with other devices within the wellbore 114.
To access the production intervals 108a-108n, the wellbore 114
penetrates the sea floor 106 to a depth that interfaces with the
production interval 108a-108n. The wellbore may be drilled
horizontally, vertically, or at any variety of directions, as
indicated by the directionally drilled wellbore of FIG. 1. As may
be appreciated, the production intervals 108a-108n, which may be
referred to as production intervals 108, may include various layers
or regions of rock that may or may not include hydrocarbons and may
be referred to as zones. As described initially above, the tree
104, which is positioned over the wellbore 114 at the sea floor
106, provides an interface between devices within the wellbore 114
and the production facility 102. Accordingly, the tree 104 can be
coupled to a production string 120 to provide fluid flow paths
between the production intervals 108 and the control umbilical 112
and any other tubes, pipes, lines, or other apparatus disposed
outside of the wellbore for the purpose of collecting or handling
the produced fluids and/or controlling and/or monitoring the
operations.
Within the wellbore 114, the production system 100 may include
additional equipment to provide access to the production intervals
108a-108n. For instance, a surface casing string 116 may be
installed from the sea floor 106 to a location at a specific depth
beneath the sea floor 106. Within the surface casing string 116, an
intermediate or production casing string 118, which may extend down
to a depth near the production interval 108, may be utilized to
provide support for walls of the wellbore 114. The surface and
production casing strings 116 and 118 may be cemented into a fixed
position within the wellbore 114 to further stabilize the wellbore
114. Within the surface and production casing strings 116 and 118,
a production tubing string 120 may be utilized to provide a flow
path through the wellbore 114 for hydrocarbons and other fluids.
Production tubing string 120 refers to the collection of pipes and
pipe sections extending from the sea floor into the wellbore.
Accordingly, the production tubing string includes conventional
production tubing as well as tool sections and other tubular
members that couple to the production tubing along the length of
the wellbore.
Along the length of the production tubing string, a subsurface
safety valve 122 may be utilized to block the flow of fluids from
the production tubing string 120 in the event of rupture, break, or
other unexpected events above or below the subsurface safety valve
122. Further, packers 124a-124n may be utilized to isolate specific
zones within the wellbore annulus from each other. The packers
124a-124n may include external casing packers, such as the
SwellPacker.TM. (Halliburton), the MPas.RTM. Packer (Baker Oil
Tools), or any other suitable packer for an open or cased wellbore,
as appropriate.
In addition to the above equipment, other devices or tools, such as
flow control systems 200a-200n, may be utilized to manage the flow
of fluids and/or particles into the production tubing string 120.
The flow control systems 200a-200n, which may herein be referred to
as flow control system(s) 200, may include pre-drilled liners,
slotted liners, stand-alone screens (SAS), pre-packed screens,
wire-wrapped screens, membrane screens, expandable screens and/or
wire-mesh screens. The flow control systems 200 are described
further herein in connection with other Figures. The flow control
systems 200 may manage the flow of hydrocarbons and other fluids
and particles from the production intervals 108 to the production
tubing string 120.
As noted above, many wells have a number of completion intervals
and the hydrocarbon/water contact relationship as well as the
sanding tendency may vary from interval to interval and over time
within a single interval. The current ability to predict the timing
and location of the onset of sand and/or water is limited. In many
wells, commingling of production intervals 108a-108n may be
preferred to simplify well completion and well production and to
maximize economic benefit, which is particularly true for deep
water wells, wells in remote areas, and/or for the capture of
marginal reserves. A major risk in these applications is that sand
failure and/or water breakthrough in any one interval threatens the
hydrocarbon production efforts as well as any remaining reserves
recovery.
To address these concerns, various sand and water control methods
are commonly used. For instance, typical sand control methods
include stand-alone screens (also known as natural sand packs),
gravel packs, frac packs and expandable screens. These methods
limit sand production but are not designed to limit or prevent a
particular fluid production (i.e., fluid control is the same
regardless of what type of fluid is being produced, whether
hydrocarbon, water, or otherwise). Furthermore, typical mechanical
water control methods include cement squeezes, bridge plugs,
straddle packer assemblies, and/or expandable tubulars and patches.
In addition, some other wells may include chemical isolation
methods, such as selective stimulation, relative permeability
modifiers, gel treatments, and/or resin treatments. These methods
require well interventions and the results have not been consistent
due to complexity in predicting the timing, location, and mechanism
of water production during the well lifetime. In certain
environments, such as deep water wells, high-pressure, high
temperature wells, and wells in remote regions, well intervention
is often expensive, risky, and sometimes not even possible.
Despite the variety of methods utilized, available technology for
controlling water production is generally complex and expensive.
Indeed, the high cost and complexity of conventional flow control,
remote control technologies, and intervention costs that are
utilized to manage water and/or sand problems often drive costs for
marginal projects beyond the economic limit for a given well or
field. Uncontrollable water production in a well may result in loss
of hydrocarbon production and/or require drilling new wells in the
region. A simple, lower cost alternative is still needed to lower
the economic threshold for marginal reserves and to enhance the
economic return for other wells and fields. Exemplary flow control
systems 200 are shown in greater detail in FIGS. 2-13 below.
FIGS. 2A-2C are schematic views of an exemplary flow control system
200 according to the present disclosure. In FIGS. 2A-2C a
representative embodiment of various components of the flow control
system 200 is shown, including such components as a base pipe 202,
an outer jacket 204, an outer permeable region 206, an inner
permeable region 208, chamber isolators 210, and particulate packs
212. These components are utilized to manage the flow of water and
particles into the production tubing string 120, and more
particularly to manage the flow of water into the base pipe
202.
With reference to FIGS. 2A-2C, the general construction of an
exemplary embodiment of a flow control system 200 is shown. FIG. 2A
illustrates a side view of a representative flow control system 200
showing an outer jacket 204 having an outer impermeable region 214
and an outer permeable region 206. The outer jacket 204 may be made
of any suitable materials and in any suitable manner of
construction. Exemplary methods and materials may be found in the
teachings of conventional sand control systems, such as
wire-wrapped screens and coating materials. While FIG. 2A
illustrates an outer jacket 204 having outer permeable regions 206
and outer impermeable regions 214, suitable flow control systems
200 may be constructed without outer impermeable regions 214.
The outer permeable region 206 may be made permeable to
hydrocarbons and other fluids through any suitable methods such as
the provisions of slits, perforations, spaces between wrapped wire,
etc. In some embodiments, the outer permeable region 206 may be
configured to at least partially block sand and other particulate
material from the production intervals 108 and/or the subsurface
formation 107, which particulate material from the production
intervals 108 and the subsurface formation 107 is referred to
herein as formation particulates (as opposed to particulate
material that is a component of the flow control system, as
discussed below).
FIG. 2A, in combination with FIGS. 2B and 2C, further illustrates
that the representative flow control system 200 includes a
plurality of flow control chambers 220, having a chamber length 222
defined by the longitudinal space between chamber isolators 210. As
illustrated, the outer permeable region 206 is longitudinally
offset from the inner permeable region 208 such that the outer
permeable region 206 and the inner permeable region 208 do not
overlap. In such implementations, the chamber length 222 may be
determined by the sum of the lengths of the inner and outer
permeable regions 206, 208, and may be still longer. The size of
the outer and inner permeable regions 206, 208 may vary depending
on the conditions of the well, such as the length of the production
interval 108, the expected stability of the subsurface formation,
the expected water content of the reservoir and/or surrounding
area, the expected longevity of the well, etc. For example, shorter
chamber lengths may be preferred in implementations for shorter
intervals to provide tight control over the interval. Similarly,
longer chamber lengths may be preferred for implementations in
longer intervals to provide suitable control over the length of the
interval. The preferred level of fluid control in a particular
interval may be determined by the characteristics of the interval
itself and/or may be determined by the local experience of the well
operators. Similarly, while the flow control chambers are
illustrated as being in continuing succession from one to the next,
some implementations of the flow control systems herein may dispose
flow control systems along the length of the production string with
otherwise conventional production tubing separating the flow
control systems. Such an implementation is shown schematically in
FIG. 1.
While flow control systems of the present invention may vary in the
size of the permeable regions, the size of the flow control
chambers, the relationship between flow control chambers, the
location of flow control chambers within the wellbore, and other
specifics, the principles of the present disclosure that provide
the flow control features persist across the various embodiments
described, suggested, and/or alluded to herein. At least some of
these principles are illustrated in FIGS. 2B and 2C, which provide
schematic side views of the representative flow control system of
FIG. 2A including partial cutaway views to illustrate elements of
the operation of the flow control system 200.
FIG. 2B illustrates via the partial cutaway schematic that the flow
control system 200 can include multiple flow control chambers 220,
such as the two and one half chambers shown. Additionally, FIG. 2B
illustrates that within the outer jacket 204 and outside the base
pipe 202 lies a consolidated particulate pack 212, which may also
be referred to as a particulate composition 212. Accordingly, the
particulate composition 212 is disposed in an external flow area
(best seen in FIGS. 3-5). As illustrated in FIG. 2B, the
particulate composition 212 initially is disposed in association
with the outer permeable region 206 underlying the outer permeable
region 206 and not overlapping the inner permeable region 208. FIG.
2B illustrates in the two distinct flow control chambers 220a and
220b two different flow scenarios that may be encountered during
production. In flow control chamber 220a, fluids consisting
primarily, if not entirely, of hydrocarbons (hydrocarbon-rich fluid
224) are illustrated as entering through the outer permeable region
206 and passing through and/or around the particulate composition
212. In contrast, flow control chamber 220b is experiencing an
inflow of fluids containing water (water-rich fluid 226). As it is
rare that fluids from a production interval will be exclusively
hydrocarbon or exclusively water, the distinction between
hydrocarbon-rich fluid 224 and water-rich fluid 226 may be quite
fine, and may be defined by the operator of the wellbore according
to the principles described herein.
With reference to FIG. 2C and with continuing reference to FIG. 2B,
it can be seen that the particulate composition 212 responds
differently to the different fluids 224, 226. FIG. 2C illustrates
that the hydrocarbon-rich fluid 224 continues to flow through the
particulate composition 212 in flow control chamber 220a. FIG. 2C
further illustrates that flow control chamber 220b has responded to
the inflow of water-rich fluid 226 and has effectively closed the
inner permeable region 208 of the flow control chamber. In summary,
the particulate composition 212 of flow control chamber 220b has
responded by releasing the particles of the particulate composition
allowing them to flow with the incoming fluids to the inner
permeable region 208, where the released particles 228 are retained
by the inner permeable region 208 to form a particulate
accumulation 230. The particulate accumulation 230 closes, or at
least substantially closes, the inner permeable region 208, which
hinders, limits, prevents, or at least substantially prevents
water-rich fluid 226 from entering the base pipe 202. Accordingly,
the flow control chamber 220b acts to control water production from
production intervals. Because water production often brings with it
sand production, the closure of flow control chamber 220b will also
help reduce sand production. Produced fluids 226 that would have
otherwise entered the base pipe in flow control chamber 220b may
proceed outside of the outer jacket 204, such as within the
production interval 108, and attempt to enter through flow control
chamber 220a. As the fluids entering flow control chamber 220a are
contaminated by undesired fluids 226, it too can respond to the
undesired fluids by releasing particles to close the flow control
chamber 220a.
With FIGS. 2A-2C providing a representative embodiment and
illustrating several principles and features of the present flow
control systems 200, many variations on the specific embodiment
shown can be appreciated. For example, FIGS. 2A-2C illustrate a
flow control system 200 utilizing a base pipe 202 and an outer
jacket 204 where the outer jacket was illustrated and described
after the manner of production tubing strings incorporating sand
control features such as outer and inner screens. However, outer
jacket 204 need not be associated with the production tubing string
120 and may be provided by the production casing string 118 where
the outer permeable region 206 is provided by the perforations in
the casing. Such an implementation is schematically illustrated in
FIG. 7 and will be further described in connection therewith below.
Additionally or alternatively, the flow control systems 200 within
the present invention may include inner and outer permeable regions
208, 206 that are not longitudinally offset one from the other as
illustrated in FIGS. 2A-2C. For example, there may be partial or
complete overlap of the two permeable regions, as shown in FIGS. 9,
11, and 12 and described in connection therewith.
The flow control systems 200 presented herein provide a base pipe
202, or other production tube designed to carry the desired
production fluids, having discrete permeable regions that allow
fluids to enter the internal flow channel of the base pipe 202. The
base pipe 202 at least partially defines an external flow area in
which is disposed a particulate composition 212 adapted to release
particles when exposed to certain triggering conditions, such as
water. The released particles then flow within the external flow
area and accumulate at the permeable regions to hinder, block, or
otherwise limit or prevent the flow of fluids into the base pipe
internal flow channel, or to otherwise form a particulate plug to
completely or at least substantially block the flow of fluids into
the base pipe. Some implementations may include elements to further
define flow control chambers 220 allowing more refined control of
fluid flow and/or to facilitate the accumulation of released
particles in desired regions within the external flow area, such as
illustrated and discussed more clearly in connection with FIGS.
5A-5F.
The consolidated particulate pack 212 may be configured in any
suitable manner to be disposed within the external flow area as
described above. At least some suitable configurations will become
apparent from the descriptions and figures provided herein; others
are also within the scope of the present invention. The particulate
pack or particulate composition 212 may be formed by consolidating
or cementing any suitable particles together in the desired manner.
In some implementations, the binding or cementing agent may be
based on alkali metal silicates. Exemplary alkali metal silicates
may be single-phase fluids adapted to cure into cementing material
at elevated temperatures. For example, potassium silicate and urea,
potassium silicate and formamide, or ethylpolysilicate, HCl, and
ethanol can be combined to provide an acceptable binding agent.
Other suitable binding materials may be used including other alkali
metal silicates and other materials.
Alkali metal silicates may be suitable binding agents when the
triggering fluid (or fluid that triggers the release of particles)
is water. That is, when the flow control systems 200 are configured
to control fluid flows from the production intervals to limit water
production, the binding agents may be selected to respond to the
presence of water, such as described in connection with FIGS. 2B
and 2C. Flow control systems 200 may similarly be configured to
respond to the presence of other fluids or materials in the fluids
from the production interval 108. For example, binding agents may
be selected to respond to the presence of natural gas causing flow
control chambers 220 to close or seal when natural gas is produced
or when natural gas is produced in quantities or rates greater than
an acceptable level. Such a configuration may allow operators to
control the gas production, thereby controlling the natural drive
pressure in the reservoir. Similarly, the binding agents may be
selected for sensitivity to other chemicals or materials in the
produced fluids, such as the presence of hydrogen sulfide, that are
preferably not drawn through the base pipe.
It should be noted that different flow control chambers along the
same production tubing string may be configured to respond to
different triggering fluids based on the estimates or knowledge of
the conditions in the relevant production intervals 108, such as
whether the production interval is gas-rich or water-rich.
Regardless of the triggering condition for which the flow control
chamber and/or system is designed, the binding agents selected to
consolidate the particles are preferably selected to be compatible
with the remainder of the wellbore operations, such as not being
harmful to the equipment or unreasonably difficult to separate from
the produced fluids.
With continuing reference to the binding agents or cementing
materials used to form the particulate pack 212, the type of agent
used and its strength and material properties may be selected to
control the rate of dissolution of the cementing material, or the
rate at which the particles are released when the wellbore is in
production mode. For example, the binding agents, and the
particulate composition generally, may be adapted to retain the
particles if the water concentration in the produced fluids is
below a predetermined threshold. Alternatively, the binding agents
may be selected to respond to elements such as time, temperatures,
concentrations of triggering fluids, flow rates of the produced
fluids, etc. Moreover, the configuration of the particulate pack
212 itself, including the thickness and porosity or permeability of
the particulate pack, may affect the dissolution rate and therefore
the rate at which the particles are released. Each production
interval and/or wellbore operator may have different tolerances
with respect to any one or more wellbore condition. The present
systems and methods allow an operator to control the fluid flow in
discrete sections of the wellbore based on one or more of these
conditions while not disturbing the flow in other sections of the
wellbore.
Particles suitable for use in the particulate composition 212 can
include gravel, sand, carbonate, silts, clays, or other particulate
materials, such as particles made of polymers or other materials.
For cost and compatibility reasons, natural materials such as
gravel and sand may be preferred particles for use in preparing the
particulate packs 212. However, other factors such as
controllability of particle size and packing density and/or impact
on the wellbore's production and/or equipment may encourage use of
other particulate materials. Moreover, particles of different
materials may be combined in a particulate pack depending on the
desired properties of the particulate pack and/or the resulting
particulate accumulation.
The particles selected for incorporation in the particulate pack
212 may be of consistent or varied sizes and dimensions. In
general, it may be preferred to include particles sized larger than
the slits or perforations of the inner permeable region 208 such
that the particles, or at least a majority of the particles, are
retained in the external flow area and not allowed to enter the
internal flow channel of the base pipe 202. Accordingly, the
configuration of the base pipe 202, and particularly the
configuration of the inner permeable region 208, and the selection
of the particles may be related.
As suggested by the foregoing description, the resulting
particulate accumulation has low permeability and resists flow
through the inner permeable region 208. The permeability of the
particulate accumulation 230 may depend on the particulate
materials, density, shape, size, variety, etc. Incorporation of
particles of varied sizes into the particulate pack 212 may be
accomplished by mixing differently sized particles of the same
material or by mixing different materials. For example, sand and
gravel may be incorporated into the particulate pack 212 to provide
a diversity of particle sizes. Other mixtures and compositions of
particle material types may be used. In some implementations,
particles may include materials that undergo change when exposed to
the triggering condition. For example, polymers may be used that
swell upon contact with aqueous fluids (or under other triggering
conditions). In such implementations, a relatively small
particulate pack may be used to form a larger particulate
accumulation as a result of the swelling particles. The swelling
may also promote improved blockage of the inner permeable region.
Any variety of materials may be used to provide this swelling, some
examples of which were described above.
Particle size ranges from submicron to a few centimeters may
provide a diversity of particle sizes to increase the packing
density of the accumulation 230, thereby reducing the permeability.
Exemplary particle sizes may range from about 0.0001 mm to about
100 mm. Considering particle size distribution and the inner
permeable region 208, the particles of the particulate pack 212 may
be selected to provide that at least 10% (by volume) of the
particles are larger than the openings of the inner permeable
region 208. More preferably, a greater proportion of the particles
will be larger than the openings of the inner permeable region. A
smaller proportion may also be preferred in some circumstances. In
other situations, the particles selected for the particulate pack
212 may have a diversity of sizes resulting in a uniformity
coefficient greater than about 5. The uniformity coefficient is a
measure of particle sorting and is defined to be d40/d90, as is
conventional in oilfield particle size measurements. As is
conventional, d40 indicates that 40% of the total particles are
coarser than the d40 particle size; similarly, d90 indicates that
90% of the total particles are coarser than the d90 particle size.
The particle sizes may be measured by use of any suitable
measurement apparatus. For example, sieving may be used to measure
particle sizes in the range of 0.037 mm to about 8 mm and laser
diffraction may be used to measure particle sizes in the range of
about 0.0001 mm to about 2 mm (e.g., Malvern's Mastersizer.RTM.
2000 may be used). Other systems and apparatus may be used to
measure particles outside of these ranges.
Factors other than (or in addition to) size may impact the packing
density and/or permeability of the resulting particulate
accumulation 230. For example, particle shapes and configurations
may impact the particles' ability to pack tightly in the
particulate accumulation 230. Particle shapes are not easily
controlled when working with natural materials such as sand and
gravel, but if polymer-based materials or other man-made materials
are used in the particulate pack 212 the particles may be custom
shaped to promote packing density. Additionally, the density of the
particles may affect the ability of the particles to move through
the external flow area and to pack into the particulate
accumulation 230, as may the orientation of the wellbore. The
particles may be selected to have a volume and density appropriate
for the particle size distribution desired to promote sufficiently
high packing density and sufficiently low permeability.
In some implementations of the present technology, methods may be
implemented to determine or design a preferred particulate
composition 212. As one exemplary method, particles if differing
sizes and/or configurations may be selected and mixed based on a
predicted, estimated, and/or calculated accumulation profile under
expected wellbore conditions. The selected and mixed particles may
then be measured to determine the size distribution and/or
uniformity coefficient, which step may not be necessary if the
particle selection process is sufficiently controlled. The
particles are then released into a prototype flow control chamber
or a mock-up version of a flow control chamber run under expected
wellbore conditions. The particulate accumulation is then allowed
to form and its permeability is measured. If the permeability is
sufficiently low, the particle selection mix may be determined to
be suitable for wellbore applications similar to those tested. If
the permeability is too high, the methods may be repeated until a
suitable particle size and configuration mix is identified. In some
implementations, the particulate mixture may result in some
particulates being produced through the inner permeable region 208
before the particulate accumulation is sufficiently formed to block
the flow. The amount of particulate production may be controlled to
any desired level by adjusting the particle size, shape, mixture,
etc., as well as by changing the size of the openings in inner
permeable region 208.
Continuing with the discussion of the composition of the
particulate pack, an exemplary particulate pack may include
particles of different sizes wherein the different sizes are of
different materials. Using particles of different materials or
compositions may enable the flow control chambers to provide a
reversible particulate accumulation to selectively block and
subsequently allow flow through the inner permeable region. For
example, it may be desirable to provide a flow control chamber that
blocks the flow of production fluids through the chamber when the
production fluids includes more than a predetermined concentration
of gas. Accordingly, the particulate pack may be adapted to release
the mixed-size, mixed-composition particles when the production
fluid meets the predetermined condition. The use of larger and
smaller particles enables the smaller particles to effectively seal
the inner permeable region against gas flow. However, it may be
desirable at some later time to allow the gas to flow through the
chamber. As one exemplary scenario, it may be desirable to limit
the gas flow to maintain the natural driving force of the well for
a time to produce as much of the liquid production fluids as
practicable. However, at a later time, it may be preferred to draw
those gases from the well.
In such circumstances, the reversible particulate accumulation may
be triggered to open the inner permeable region. The reversible
particulate accumulation may be triggered by pumping a reversal
fluid into the wellbore, which may be done through any suitable
methods. Continuing with the exemplary scenario presented, the
reversal fluid may dissolve or otherwise affect the smaller
particles while leaving the larger particles in place. The
dissolution of the smaller particles may open voids sufficiently
large to allow the gaseous production fluids through the inner
permeable region. In some implementations, the voids created may be
sufficiently small to limit or significantly restrict the flow of
liquids through inner permeable region. In other implementations of
a reversible particulate accumulation, the particles may all be
made of similar size and/or of the same material and the reversal
fluid may dissolve or otherwise remove the accumulation in whole or
in part. Accordingly, the selection of the particle sizes and
materials may be informed at least by the conditions of the
production interval and the conditions to be monitored for
triggering the particulate accumulation and by the conditions that
may motivate a reversal of the particulate accumulation.
While FIGS. 2A-2C provide a schematic illustration of a
representative implementation of the present technology and a
backdrop for discussion of several principles and features of the
present disclosure and invention, FIGS. 3-13 provide illustrations
of additional representation embodiments and implementations to
further illustrate the scope of the present invention. While
several examples are provided in the Figures, the scope of the
present invention extends beyond the relatively limited number of
implementations shown and includes all variations and equivalents
of the illustrated embodiments and of the claims recited below.
FIG. 3 and FIGS. 4A-4C provide similarly schematic representations
of the present technology, including a consolidated particulate
pack disposed in an external flow area. FIGS. 3 and 4A each
represent an alternative initial configuration of a flow control
chamber 220, where the illustrated difference is in the disposition
of the particulate pack 212. Beginning with FIG. 3, a portion of a
flow control system 200 is shown schematically disposed in a
production interval containing production fluids 109. Similar to
the illustration of FIGS. 2A-2C, the flow control system 200
includes a base pipe 202 having an inner permeable region 208 and
includes an outer jacket 204 having an outer permeable region 206.
The outer jacket 204 illustrated is representative of the various
suitable outer jackets discussed above, such as an outer screen
member, a length of production casing, etc. The space between the
outer jacket 204 and the base pipe 202 defines an external flow
area 216 within the flow control chamber 220. The production fluids
109 from the production interval pass through the outer permeable
region 206 into the external flow area 216 and then pass through
the inner permeable region 208 into the internal flow channel 218,
as shown by flow arrows 232.
FIG. 3 illustrates the particulate pack 212 disposed within the
external flow area 216 and near the inner permeable region 208 (as
compared to the embodiment illustrated in FIG. 4A). The particulate
pack 212 is disposed so as to be contacted by the production fluids
109 flowing through the external flow area 216. As illustrated, the
production fluids 109 contact the particulate pack as the fluids
flow around the edges of the pack 212. In some implementations, the
particulate pack 212 may be porous or otherwise configured to allow
production fluids 109 to flow through the pack or portions of the
pack. As discussed above and better illustrated in FIGS. 4A to 4C,
the particulate pack 212 is adapted to release the particles when
contacted by triggering fluids and/or triggering conditions (such
as time, concentration of particular chemicals or fluids, elapsed
exposure time to particular conditions, etc.) and the inner
permeable region 208 is adapted to retain at least some of the
released particles to form a particulate accumulation blocking the
inner permeable region.
FIGS. 4A to 4C illustrate yet another possible configuration of the
particulate pack 212 within an external flow area 216. FIG. 4A
illustrates all of the same components as FIG. 3 but disposes the
particulate pack at the opposing end of the flow control chamber
220 from the inner permeable region 208. As flow control chambers
220 may be provided in any suitable length or configuration with
the inner and outer permeable regions disposed in any suitable
position relative to each other and to the overall length of the
flow control chamber, the various views of FIGS. 2-4 illustrate
merely exemplary configurations, which are not limiting to
distances, shapes, or configurations of the particulate pack. With
the particulate pack 212 disposed in the external flow area 216 and
in a flow path defined therein for the production fluids 109
enroute to the internal flow channel 218, the particulate pack 212
is able to respond to the conditions of the production fluids and
to close the flow control chamber as appropriate.
FIGS. 4B and 4C illustrate the effects of the triggering fluid on
the particulate pack 212. FIG. 4B schematically represents the
condition of the flow control chamber 220 after the production
fluids 109 have exposed the particulate pack 212 to trigger fluids
and/or triggering conditions for a sufficient amount of time to
release all of the particles (released particles 228) that had been
consolidated into the particulate pack. FIG. 4B illustrates all of
the released particles 228 in motion at the same time (i.e., not
yet forming a particulate accumulation 230). Such a state may exist
in a flow control chamber 220 when the particulate pack 212 is
configured with a binding agent selected to quickly release the
particles once a triggering condition is encountered. Alternative
binding agents and/or particulate pack configurations may have a
slower release that retains at least some particles in the
particulate pack 212 long enough that the released particles 228
begin to form a particulate accumulation 230 before the last
particles are released.
FIG. 4C illustrates a flow control chamber 220 in a closed
condition. More specifically, the released particles have formed a
particulate accumulation 230 adjacent to the inner permeable region
208 to seal, or least substantially seal, the inner permeable
region. As indicated by flow arrows 232, the flow of production
fluids 109 into the flow control chamber 220 is blocked, or at
least substantially blocked, by the particulate accumulation 230.
The particulate accumulation 230 is illustrated schematically; it
will be appreciated that actual particulate accumulations may not
be formed with such precise and defined boundaries. Moreover,
particulate accumulations 230 may be formed to completely fill the
external flow area adjacent the inner permeable region 208 or the
flow control system 200 may be configured to form a particulate
plug that acts to block the fluid flow within the external flow
area 216. The manner in which the released particles 228 accumulate
in the external flow area 216 will be dependent upon a number of
factors, including the size, shape, and density of the particles,
the configuration and condition of the external flow area 216, and
other properties of the wellbore and/or produced fluids, as
described at least in part above and as illustrated in other
Figures of the present disclosure.
Turning now FIGS. 5A to 5F, various views of an exemplary flow
control systems are illustrated. In the representative embodiment
illustrated in FIGS. 5A-5F, the flow control system 300 is
configured as a pair of concentric tubes designated as a first
tubular member 302 and second tubular member 304, such as may be
incorporated into a production tubing string. FIGS. 5A and 5B
provide perspective and end views, respectively, of the first
tubular member 302; FIGS. 5C and 5D provide perspective and end
views, respectively, of the second tubular member 304; and FIGS. 5E
and 5F provide perspective and end views, respectively, of the
first and second tubular members assembled to provide a flow
control system 300 including a plurality of flow control chambers
320.
FIGS. 5A and 5B illustrate an embodiment of the base pipe 302 and
axial rods 334, which are illustrated as being coupled together.
The base pipe 302, which may be referred to as an inner flow tube
or a first tubular member, may be a section of pipe that has an
internal flow channel 318 and one or more openings, such as slots
336, providing an inner permeable region 308. The axial rods 334,
which may be disposed longitudinally or substantially
longitudinally along the base pipe 302, can be coupled to the base
pipe 302 via welds or other similar techniques. For instance, the
rods 334 may attach to the base pipe 302 via welds and/or be
secured by end caps with welds. Additionally or alternatively, the
axial rods 334 may be held in place by the cooperation of the first
tubular member 302 and the second tubular member 304 applying
pressure on the axial rods. As further alternatives, the axial rods
334 may be coupled to the second tubular member 304 (FIGS. 5C and
5D) in any suitable manner. For example, the axial rods 334 may be
welded to the second tubular member 304, which may be configured to
press the axial rods against the first tubular member 302.
Additionally or alternatively, the axial rods 334 may be disposed
in recesses in the first and/or second tubular members to retain
the axial rods in the proper orientation. The base pipe 302 and the
axial rods 334 may include carbon steel or corrosion resistant
alloy (CRA) depending on the level of corrosion resistance desired
or needed for a specific application. The selection of materials
may be similar to selection of materials for conventional screen
applications. For an alternative perspective of the partial view of
the base pipe 302 and axial rods 334, a cross sectional view of the
various components along the line 5B is shown in FIG. 5B.
With continuing reference to FIG. 5A, the slots 336 are adapted to
provide the inner permeable region 308 discussed above.
Accordingly, the slots 336 may be adapted to prevent the passage of
at least some of the particles released from the particulate pack
used with the particular flow control system 300. For example, the
width and/or length of the slots may be modified in light of the
particle size distributions of the particulate pack.
FIG. 5A further illustrates that the slots 336 of the inner
permeable region 308 are disposed adjacent to the chamber isolators
310. The chamber isolators 310 may be of the same or different
materials as the base pipe 302 and/or the axial rods 334. The
material selected for the chamber isolators 310 may be durable to
withstand the conditions of the external flow area (e.g. abrasion,
pressure, etc.). The chamber isolators 310 may be coupled to the
base pipe 302 and/or the axial rods 334 by welding or other
conventional techniques, which may include one or more of the
techniques described above for the axial rods. Chamber isolators
310 may be disposed adjacent to each inner permeable region 308, as
illustrated, or may be spaced away from the inner permeable region.
Additionally or alternatively, flow control chambers 320, defined
by the space between adjacent chamber isolators 310, may include
more than one inner permeable region 308.
In some implementations, the released particles may need the
assistance of a chamber isolator 310 to begin accumulating over an
inner permeable region 308. In other implementations, the
configuration of the external flow area 316 (see FIG. 5F) may be
sufficient to cause the released particles to begin accumulating
and to form a plug. For example, the length and cross-section areas
of the external flow areas 316 (the areas between the axial rods
334) may be such that the released particles naturally accumulate
and form a particulate plug in the external flow area. As an
additional example, the external flow area may be an area between a
base pipe and a casing string wherein gravel pack or fracture pack
materials are disposed in the annulus. In such implementations, the
gravel pack materials may cause the released particles to
accumulate before reaching the inner permeable region 308 and a
particulate plug may form away from the inner permeable region 308.
Accordingly, while the configuration of the inner permeable region
308 may be dependent on the configuration of the particulate pack,
it is not necessary in all implementations.
Continuing with the discussion of the slots 336 of FIG. 5A, the
slots may additionally or alternatively be adapted to provide sand
control to prevent or restrict the flow of formation particles,
such as sand, from passing between the external region of the base
pipe 302 and the internal flow channel 318. For instance, the slots
336 may be defined according to "Inflow Analysis and Optimization
of Slotted Liners" and "Performance of Horizontal Wells Completed
with Slotted Liners and Perforations." See T. M. V. Kaiser et al.,
"Inflow Analysis and Optimization of Slotted Liners," SPE 80145
(2002); and Yula Tang et al., "Performance of Horizontal Wells
Completed with Slotted Liners and Perforations," SPE 65516 (2000).
Additionally or alternatively, it is noted that the outer permeable
region 306 may be adapted to provide some degree of sand control.
It should also be noted that the inner permeable region 308 on the
first tubular member 302 may be provided by configurations other
than the slots 336. For example, mesh type screens, perforations,
wire-wrapped screens, or combinations of these or other
conventional methods of providing controlled or limited access to
base pipes may be used.
FIGS. 5C and 5D illustrate a second tubular member 304 that may be
disposed around the first tubular member 302 and axial rods 334 of
FIGS. 5A and 5B. FIG. 5C provides a perspective view while FIG. 5D
provides a cross-sectional view along line 5D. The second tubular
member 304, may be a section of pipe with openings or perforations
338 along the length thereof. The second tubular member 304 may
include carbon steel or CRA, as discussed above in connection with
the first tubular member. Other suitable materials may be used
depending on the expected conditions under which the flow control
system will be used.
The perforations 338 are one example of a suitable method of
forming an outer permeable region 306. The perforations 338 may be
sized to minimize flow restrictions (i.e. sized to allow particles,
such as sand to pass through the perforations 338) or may be
sufficiently small to limit the flow of sand and/or other formation
materials. The perforations may be shaped in the form of round
holes, ovals, and/or slots, for example. While the outer permeable
region 306 may be provided by perforations 338, the outer permeable
region may be provided in any suitable manner, such as by slots, as
described above, by wire-wrapped screen, by mesh screen, by
sintered metal screen, or by other conventional methods, including
conventional sand control methods. In some implementations, the
openings of the outer permeable region 306, whether by perforations
338 or otherwise, can be sized to retain the released particles
from the consolidated particulate packs of the present disclosure.
Accordingly, the configuration of the outer permeable region 306
may be dependent upon the choice of materials for the particulate
packs and vice versa.
Considering FIGS. 5A, 5C, and 5E, it can be seen that both the
first tubular member 302 and the second tubular member 304 are
configured with permeable regions and impermeable regions. More
specifically, it can be seen in FIG. 5E that the first tubular
member 302 is configured with an inner permeable region 308 and an
inner impermeable region 324 and that the second tubular member is
configured with an outer permeable region 306 and an outer
impermeable region 314. FIG. 5E similar to the Figures described
above, illustrate the inner and outer permeable regions 308, 306 in
offset dispositions or configured such that the permeable regions
do not overlap each other. While an offset configuration is
suitable for flow control devices, such a configuration is not
required for the successful implementation of the present
invention, as will be seen through the schematic illustrations of
FIGS. 9-14.
The use of permeable and impermeable regions in the first and
second tubular members allows for the possibility of a changed-path
flow chamber in the flow control system. The changed-path flow
chamber effectively acts as a baffle or flow diversion means to
redirect the flow from a radially incoming direction to a
longitudinal direction and/or circumferential direction. While not
required for the practice of the present invention, implementation
of a configuration providing a changed-path flow chamber may
provide additional features to the flow control systems of the
present invention. For example, the flow redirection may reduce the
energy in the incoming produced fluid, which may result in
prolonging the usable life of the inner permeable region 308.
The usable life of the inner permeable region 308 may be prolonged
by reducing the pressures and forces that tend to penetrate the
screens or meshes of the inner permeable region. It is known that
screens and meshes conventionally used in sand control devices have
a tendency to tear or otherwise create openings defeating the
purpose of the sand control device. These openings are caused, at
least in part, by the forces applied on the screen by the
particle-laden fluids flowing directly onto or through the screen.
The risk of the screen yielding to these forces is particularly
greater in localized "hot spots" (e.g., where production flows are
concentrated due to plugging in surrounding areas). These localized
hot spots may form due to a variety of circumstances within the
wellbore, many of which are not controllable by the well operators.
In some implementations, the changed-path flow control chamber may
be configured to redistribute the energy of the incoming production
fluids and to reduce the energy of the hot spots while slightly
increasing the energy applied to the rest of the inner permeable
region 308. The redistribution of the forces across the surface
area of the inner permeable region 308 prolongs the life of the
inner permeable region.
When a changed-path flow chamber is implemented, the outer
permeable region may be configured in a variety of suitable
manners. For example, it may be preferred to configure the outer
permeable region to control the inflow of formation particles that
may prematurely block the inner permeable region. Additionally or
alternatively, it may be preferred to configure the outer permeable
region to resistance tearing or opening under the pressures of the
production fluid.
Once the production fluids pass through the outer permeable region
306, the production fluids are redirected and flow through the
external flow area en route to the inner permeable region 308 where
the fluids must again change directions to pass through the inner
permeable region and into the internal flow channel 318. As the
production fluids flow through the external flow area, the energy
is redistributed across the flow profile and the risk of hot spots
in the inner permeable region 308 is minimized. Depending on the
configuration of the wellbore and the flow control system, this
turn at the inner permeable region 308 may be a 180 degree turn, or
a U-turn, to join the flow in the internal flow channel. The
chamber isolators 310 may be configured to endure the forces that
would be applied thereon in light of this fluid redirection at the
inner permeable region 308. As can be seen, the fluid flow
impacting the inner permeable region 308 has been baffled or
redirected at least twice and its energy reduced and/or distributed
accordingly. Without being bound by theory, it is believed that
implementation of a changed-path flow chamber will result in an
inner permeable region 308 having a longer life and/or an inner
permeable region more capable of enduring a variety of wellbore
conditions. Additionally or alternatively, the changed-path flow
chamber may allow the inner permeable region 308 to be provided by
a greater diversity of configurations and/or materials.
FIGS. 5E and 5F illustrate an embodiment with the second tubular
member 304 disposed around the first tubular member 302 and axial
rods 334. The second tubular member 304 can be secured to the first
tubular member 302 via coupling to the axial rods 334. This
coupling may be made by welds or other similar techniques, as noted
above. As one example, the second tubular member 304 may be
provided with one or more grooves or slots (not shown) in the
interior surface adapted to receive one or more of the axial rods
334. The second tubular member 304 may then be slid onto the first
tubular member 302 and the axial rods 334 with the relationship
between the axial rods 334 and the grooves on the second tubular
member maintaining the desired rotational orientation between the
first and second tubular members. The assembly of the first tubular
member 302, the second tubular member 304, and the axial rods 334
may then be coupled together by welding at the longitudinal ends
340 of a section of the flow control system 300. Additionally or
alternatively, the sections of the flow control system may
terminated by end caps (not shown), which may be welded or
otherwise coupled to one or more of the first tubular member 302,
the second tubular member 304, the axial rods 334, and the chamber
isolator(s) 310. Alternatively, the axial rods 334 may be secured
to the second tubular member 304 and the combination then slid onto
the first tubular member 302, which assembly can be completed and
coupled together in any suitable manner, such as using end
caps.
FIG. 5F provides a cross-section view of the assembly illustrated
in FIG. 5E, including the first tubular member 302, the second
tubular member 304, and the axial rods 334. FIG. 5F further
illustrates the internal flow channel 318 and the external flow
area 316. It should be noted that FIGS. 5A-5F illustrate the use of
eight axial rods 334 in particular rotational orientations around
the first tubular member 302, but that such a configuration is
merely exemplary of the suitable configurations for an external
flow area 316 that can be implemented according to the present
disclosure. The axial rods 334 may further define the external flow
area by breaking the annulus into discrete flow channels, but the
quantity and configurations of such discrete channels may be varied
to meet the conditions in the wellbore and/or the configuration of
the flow control system. For example, greater or fewer axial rods
may be provided, including the possibility of using no axial rods
at all. Moreover, the axial rods 334 can be circumferentially
spaced evenly around the annulus or may be disposed in particular
locations based on the conditions of the wellbore. For example, an
angled or horizontal wellbore may suggest a configuration for the
flow control system 300 different from a configuration that is best
suited for a vertical wellbore. Alternatively, the axial rods may
be provided in more complex patterns, such as non-linear or non
parallel patterns.
FIG. 6 illustrates an embodiment of an assembled member 442 of a
flow control system 400 with end caps 444 disposed around the first
tubular member (not shown), the axial rods (not shown), and second
tubular member 404. The end caps 444 illustrated are by way of
example only as the end caps can be provided in any suitable
configuration while staying within the scope of the present
disclosure. The specifics of configuration for a particular flow
control system 400 may vary for different wellbores and/or for
different use conditions. For example, the end caps 444 may be
adapted to facilitate the coupling together of adjacent members of
the flow control system and/or may be adapted to facilitate the
coupling of a flow control system member to other members of a
production tube.
As illustrated in FIG. 6, each of the end caps 444 includes neck
regions 446 that include threads 448 utilized to couple the member
442 of the flow control system with other members of the flow
control system, sections of pipe, and/or other devices. The end
caps 444 may be coupled to the second tubular member 404, the axial
rods (not shown), and/or the first tubular member (not shown) at
neck regions 446, such as in sections 450 where the neck region 446
is adapted to fit to the remaining components of the flow control
system member 442. In the neck regions 446, the end caps 444, the
second tubular member 404, the axial rods (not shown), and the base
pipe (not shown) may be welded together in a manner similar to that
performed on wire wrapped screens. The first tubular member (not
shown) may extend beyond either end of the second tubular member
404 to provide room for tubing connections, for connecting members
of flow control systems together, or for connecting other tools
with the flow control system member 442.
FIG. 6 also illustrates features and principles related to the
construction of a flow control system such as illustrated in FIG.
1. As illustrated in FIG. 1, the production string 100, and more
particularly the tubing string 120, includes a plurality of flow
control systems 200, with one system 200 disposed in association
with each of the production intervals 108. The flow control systems
200 of FIG. 1 can be provided by a single member 442 of FIG. 6 or
can be provided by a combination of two or more members 442. As one
example when the use of multiple flow control system members 442
may be practical is when the particular production interval 108 is
larger than would be practical to use a single member. As another
example, it may be practical to utilize multiple members when a
particular production interval 108 is believed to have different
conditions that might justify different treatments. For example,
one region of the interval may be more concerned with the control
of water while another region may be more concerned with the
production of hydrogen sulfides or other unwanted chemicals. In
such circumstances, a first flow control member can be configured
to respond to water as the triggering fluid while a second flow
control member can be configured to respond to the other undesired
condition.
FIG. 6 further illustrates that a single flow control member 442
may be configured to include more than one flow control chambers
420. As above, a flow control chamber 420 is the space between
chamber isolators (not shown). The flow control chambers 420 in a
single flow control member 442 may be similarly configured or may
be configured differently. For example, the configuration of the
permeable regions may vary between the chambers, the sensitivity
and/or triggering fluids/conditions for the particulate pack may
vary between chambers, or other of the parameters discussed herein
may be varied to suit the conditions under which the flow control
system 400, the particular flow control member 442, and/or the
particular flow control chamber 420 will be used.
FIG. 7 is a schematic representation of a flow control system 500
disposed in a wellbore 114. The flow control system 500 may
incorporate any one or more of the principles, features, and
variations described above in addition to those described here in
connection with the embodiment of FIG. 7. The wellbore 114 of FIG.
7 is a cased-hole well, which may be cased in accordance with any
of the variety of conventional techniques. In FIG. 7, a section of
the wellbore 114 is shown with flow control systems 500a and 500b
disposed adjacent to production intervals 108a and 108b. In this
section of the wellbore, packers 124a, 124b, and 124c are utilized
with the flow control devices 500a and 500b to provide separate
flow control chambers 520 associated with the separate production
intervals 108a and 108b.
In the implementation of FIG. 7, the flow control system 500 is
provided by a combination of the production tubing string 120 and
the production casing string 118 providing the first tubular member
502 and the second tubular member 504, respectively. The interior
126 of the production tubing string 120 provides the internal flow
channel 518 discussed above while the conventional annulus 128
between the production tubing string and the production casing
string 118 provides the external flow area 516 discussed above. The
packers 124 are positioned to serve as flow chamber isolators 510
defining sections of the wellbore as flow control chambers 520. The
inner permeable region 508 is provided by the slots 536 on the
production tubing string 120 and the outer permeable region 506 is
provided by the perforations 130 through the production casing
string 118 and the cement 132. A flow path 134 is defined between
the perforations 130 in the casing string and the inner permeable
region 508 that allows the produced fluids to enter the internal
flow channel of the production tubing string.
The outer permeable region 506 provided by the perforations 130
illustrates the wide range of configurations available for the
outer permeable region, which may include configurations having a
natural or artificial filtration feature or no screen or filtering
feature whatsoever. Moreover, it should be noted that the inner
permeable region 508 may be provided by any suitable adaptation of
a conventional production tubing string. For example, a
conventional production tubing sleeve may be provided with an
otherwise conventional sand control device that is further adapted
for use with the particulate packs of the present disclosure, such
as having openings sized to retain at least some of the released
particles to cause a particulate accumulation to form.
As discussed above, the flow control systems of the present
invention include a particulate pack 512 or other form consolidated
particulate material disposed in an external flow area, which is at
least partially defined by the outer surfaces of a first tubular
member 502, which here is illustrated as the production tubing
string 120. As illustrated in flow control chamber 520b, a
schematically illustrated particulate pack 512 is disposed about
the production tubing string 120 in a manner to be in the external
flow area 516 (annulus 128) and in the flow path 134. With
continuing reference to flow control chamber 520b, the fluids in
flow path 134 pass over or through the particulate pack 512 to
enter the production tubing string 120 via the inner permeable
region 508. Because the particulate pack 512 is contacted by the
fluids, the particulate pack is able to respond to changing
conditions in flow control chamber 520b without intervention from a
user.
Accordingly, should the conditions in the flow control chamber 520b
change such that a triggering condition is satisfied, particles
from the particulate pack 512 will be released, which may occur
according to any one or more of the scenarios and implementations
discussed herein. After the triggering condition is satisfied for a
sufficient amount of time, some or all of the particles will have
been released and will have formed a particulate accumulation 530,
as illustrated in flow control chamber 520a of FIG. 7. The
particulate accumulation may be of any suitable configuration to
block, or at least substantially block, fluid flow through the
inner permeable region 508 of the flow control chamber, here
chamber 520a. With reference to flow control chamber 520a, it can
be seen that fluids 552 entering flow control chamber 520a
experienced a substantially blocked flow path 554 and at least a
majority of the fluids are not allowed to enter the internal flow
channel 518.
The representative implementation of a flow control system 500
shown in FIG. 7 further illustrates that the relative positions of
the inner permeable regions 508 and the outer permeable regions 506
can vary depending on the configuration of the flow control system
and/or the conditions under which it will be operated. In several
of the preceding illustrations, the particulate packs (212 and 312)
were disposed vertically above the inner permeable regions (208 and
308) and the fluid flows were illustrated as flowing downward,
thereby benefiting by the force of gravity. In the implementation
of FIG. 7, the inner permeable region 508 is disposed vertically
above the outer permeable region 506 creating an upward directed
flow path. The upward paths of the flow control system 500 of FIG.
7 require the released particles of the particulate pack 512 to
flow against gravity to form the particulate accumulation 530
adjacent to the inner permeable region. Depending on the density of
the particles used in the particulate packs and the density of the
fluids entering the external flow area 516, such an upward
configuration may present problems. However, some implementations
of the present flow control systems may utilize particles that are
adapted to be buoyant, such as having a low density or other
configurations that promotes floating in a liquid environment. For
example, some particles suitable for use in the present invention
may include an outer shell and a hollow core reducing the mass
while maximizing the volume. Such particles may be naturally
occurring or may be custom-made for this use. Accordingly, an
upwardly-oriented flow path may utilize buoyant forces and the
force of the flowing fluids to overcome the effects of gravity
during operation.
FIG. 8 is schematic illustration similar to that of FIG. 7, but
showing the flow control systems 600 disposed in a wellbore 114 for
an open-hole multi-zone well. In FIG. 8, however, the second
tubular member 304 or outer jacket 204 discussed herein is provided
by the natural walls 604 of the wellbore. The flow path 134 for
fluids through the flow control systems 600 is from the wellbore
wall into the flow control chambers 620 and contacting the
particulate packs 612 before passing through the inner permeable
region 608. The flow control chambers 620 are created within the
annulus of the wellbore, as in FIG. 7, and may be formed with
conventional packers, still-to-be-developed packers, other tools
within the wellbore, and/or natural elements of the wellbore, such
as the end or bottom of the wellbore, each of which may be referred
to as chamber isolators when implementing the present invention.
FIG. 8, similar to the Figures above, illustrates the inner
permeable region 608 offset from the production intervals 108 of
the formation, which would result in a changed-path flow chamber,
however such a configuration is not required. The particulate pack
612 may be provided as an attachment to or as a part of the
production tubing string 120, as illustrated, or may be coupled to
or part of the packer or other device providing chamber isolators
610. The remainder of FIG. 8 is sufficiently similar to FIG. 7 that
repetition of the descriptions thereof would be superfluous. It is
sufficient to note that the particulate pack 612 (as seen in flow
control chamber 620b) breaks down when exposed to a triggering
condition and the particles from the particulate pack reform as a
particulate accumulation 630 (as seen in flow control chamber
620a). Accordingly, the flow control systems 600, in a manner
similar to the systems discussed above, provides a self-actuating
flow control system that effectively blocks flow through a region
or chamber of a production tube when an undesirable condition is
found in that region of the wellbore, such as excessive water
production.
FIGS. 9-13 provide additional schematic illustrations of flow
control chambers 720 in a pre-trigger configuration, or before the
particles of the particulate packs 712 have been released. For the
purposes of FIGS. 9-13, at least in part because of the schematic
nature thereof, the elements will be referenced by the same number
across the Figures though the configurations of those elements vary
as seen in the Figures. FIGS. 9-13 are provided to further
illustrate the variety of configurations available within the scope
of the present invention, including the variety of suitable
relationships between the outer permeable regions 706, the inner
permeable regions 708, and the particulate packs 712.
FIGS. 9-13 are schematically illustrated similar to FIGS. 3-4
above. FIG. 9 illustrates a flow control system 700 disposed
adjacent to production fluids 109. The production fluids 109 enter
an external flow area 716 through an outer permeable region 706. In
the external flow area 716, the fluids pass by and contact a
particulate pack 712. The fluids then enter an internal flow
channel 718 through an inner permeable region 708. FIG. 9
illustrates at least some of the variations discussed above. For
example, FIG. 9 illustrates that the particulate pack 712 may be
coupled to the second tubular member 704. Moreover, FIG. 9
illustrates that the outer permeable region 706 may overlap, at
least partially as shown here, the inner permeable region 708. At
least one of the benefits of the offset permeable regions 706,708
was the resulting energy reduction in the fluids contacting the
inner permeable region 708. As illustrated in FIG. 9, some of this
energy reduction benefit may be provided by the disposition of the
particulate pack 712 in the direct path from the outer permeable
region 706 to the inner permeable region. Accordingly, fluids
contacting the inner permeable region 708 have either changed
course after passing through the outer permeable region 706 or have
passed through the particulate pack 712, either of which will
distribute the energy in the fluids and minimize the possibility
for localized hot spots. However, as discussed above, the provision
of offset permeable regions and/or flow damping effects by passing
through the particulate pack 712 are not required in all
implementations of the present invention. For example, the
particulate pack 712 of FIG. 9 could be shortened at its
illustrated bottom end exposing a direct path to the inner
permeable region 708 without departing from the scope of the
present invention.
FIG. 10A is similarly schematically drawn to illustrate an
alternative configuration of the particulate pack 712. The
remainder of the elements of FIG. 10A is similar to those found in
FIG. 9 and are not discussed at length here. However, it should be
noted that the particulate pack 712 of FIG. 10A is not associated
with the permeable regions of either the first or the second tunnel
members, but is disposed in the flow path indicated by arrows 732
in the external flow area 716. It is also noted that the
particulate pack 712 of FIG. 10A is disposed so as to eliminate any
free pass or path way to the inner permeable region 708. The
particulate pack 712 may be configured to be porous or to allow
fluid to pass through the pack, such as by having pathways defined
through the pack. Porous particulate packs disposed so as to fill
the external flow area 716 may be configured in light of the
pressure drop and flow resistance imposed by such a design. While
the pressure drop caused by a flow-through particulate pack (as
compared to a flow-by particulate pack) may be undesired, such a
configuration may increase the quantity and/or quality of the
contact between the fluids and the particulate pack 712. For
example, if a rapid release of the particles is desired, the
configuration of FIG. 10A may allow the triggering condition to be
more quickly observed by a larger portion of the particulate pack
712, thereby releasing more particles in a shorter amount of time.
A quick release of the particles may be desired when the triggering
condition is particularly sensitive or significant to the operation
of the well. Other wellbore conditions may favor a delayed release
of the particles. It should also be noted that the particulate pack
712 of FIG. 10A may be coupled to the first tunnel member 702
and/or the second tunnel member 704.
FIG. 10B illustrates a variation on the configuration of FIG. 10A.
As suggested by the lack of flow arrows 732 passing through the
particulate pack 712, the particulate pack 712 of FIG. 10B fills
the external flow area 716 and is not designed to allow fluid to
pass therethrough. While some fluid may pass through the
particulate pack, the pack 712 of FIG. 10B is not designed with
pathways and is intended to block or at least substantially block
the fluid flow into internal flow channel 718. Such a configuration
may be desirable when the flow control chamber 720 is known to be
disposed in a section of the interval that will produce undesired
fluids initially followed by desired fluids. Accordingly, the plug
particulate pack 712 of FIG. 10B may be configured to open pathways
to the inner permeable region 708 when the desired fluids contact
the particulate pack. For example, the plug particulate pack 712
may include materials that are soluble in the desired fluids such
that pathways are formed in the particulate pack by the dissolution
of the soluble materials. Additionally or alternatively, the
binding materials of the plug particulate pack 712 may be adapted
to release the particles when contacted by the desired fluids. In
such a configuration, the released particles from the plug
particulate pack 712 may be selected and sized to form a porous
accumulation allowing fluid flow through the inner permeable region
708. FIG. 10B is in some respects the inverse of the configurations
discussed in the remainder of this disclosure and is an example of
the scope of the present invention. As discussed herein, the
present invention is directed to a flow control system utilizing
particulate materials that transition between at least two
accumulated or packed configurations, one of which allows fluid
flow into an internal flow channel and the other of which blocks
fluid flow into the internal flow channel, which transition does
not require user or operator intervention and occurs upon
satisfaction of a triggering condition.
FIG. 11 illustrates yet another possible configuration of flow
control systems within the scope of the present disclosure. The
flow control system 700 of FIG. 11 includes a plurality of
particulate packs 712 in the external flow area 716 spaced along
the length of a single flow control channel 720. Each of the
particulate packs 712a, 712b, 712c may be configured differently or
may be of similar construction and composition. The illustrated
positions of the particulate packs 712 are representative only and
any distribution of particulate packs may be suitable for the
present invention.
In some implementations of the present invention, a single flow
control chamber may be configured to have a staged deployment of
the flow control features. In the example of FIG. 11, the upper
particulate pack 712a may be configured to respond more quickly to
a given triggering condition releasing its particles before the
other particulate packs begin to release particles. In such
implementations, the particles of the upper particulate pack 712a
may form a particulate accumulation at the location of the middle
particulate pack 712b, effectively sealing off the upper portion of
the flow control chamber 720 while allowing fluid to continue to
enter internal flow channel through the remainder of the outer
permeable region 706. In the illustrated example of FIG. 11, such a
configuration may be desirable when an undesired fluid is known to
be present above the location of the flow control chamber. When the
undesired fluid first enters the production fluid and attempts to
enter the internal flow channel, it will be coming from the upper
end of the flow control chamber. Sealing just the upper portion may
allow the lower portions of the flow control channel to continue
producing desirable production fluids while the undesired fluid
continues to work its way toward the remaining portions of the flow
control chamber. In this respect, use of a multi-phase flow control
chamber 720 may be similar to the use of a multiple flow control
chambers in a string. It should be noted that the references to
upper, lower, above, etc. are in relation to the implementation in
the illustrated orientation and that corresponding references can
be made for implementations having different orientations. For
example, the permeable regions and particulate packs of FIG. 11 may
be configured with staged deployment of particulate accumulations
to at least substantially block undesired fluids from below the
flow control chamber 720, such as when the staged deployment is
implemented to control water production and the water is disposed
below the hydrocarbons.
FIG. 12 presents yet another schematic illustration of a portion of
a flow control system 700. In FIG. 12, the flow control system is
disposed horizontally, such as may be the case in a horizontal
wellbore. While the embodiment of FIG. 12 may be suitable for
horizontally disposed flow control systems, horizontally disposed
flow control systems of the present disclosure may include any of
the features, elements, and configurations described herein and are
not limited to the embodiment shown in FIG. 12. FIG. 12 further
illustrates an embodiment wherein the inner and outer permeable
regions 706,708 each extend the entire length of the flow control
chamber 720 rather than including impermeable regions. The flow
control chamber 720 of FIG. 12 is provided with a particulate pack
712 disposed closer to the inner permeable region 708, which may be
coupled to the inner permeable region. The production fluids 109
flow along paths 732 through the outer permeable region 706 and
into the external flow area 716, contacting the particulate pack
712 and entering the internal flow channel 718 through the inner
permeable region 708. In some implementations, the particulate pack
712 is configured with pathways or other designs to be permeable
during desired fluid production. In the event that a triggering
condition exists in the flow control chamber, such as the presence
of water, the particulate pack 712 releases some or all of its
particles as described above to form a particulate accumulation
adjacent to the inner permeable region closing the pathways in the
particulate pack and blocking or at least substantially blocking
the inner permeable region 708.
A variety of configurations may be implemented to ensure or at
least promote the desired level of blockage in the flow control
chamber, as has been discussed throughout. In the embodiment of
FIG. 12 including a full length inner permeable region, the
particulate pack 712 may be configured adjacent to the inner
permeable region in a manner such that the released particles
collapse towards the permeable region to form the accumulation.
Stated otherwise, the particulate pack 712 may be configured to
include particles spaced apart by a binding agent and may have
pores or other passages defined through the particulate pack. As
the binding agent contacts or is exposed to the triggering
condition, the particles are released and collapse into the pores
of the particulate pack and eventually collapse onto the inner
permeable region 708. Other configurations may be implemented to
encourage the released particles to accumulate in a desired manner
to form a particulate accumulation that adequately blocks the inner
permeable region. In this as well as the other embodiments
described herein, it should be noted that the particles selected
for the particulate pack and the quantity, size, shape, volume, and
density thereof can be selected to form a particulate accumulation
sufficient to block the desired portion of the inner permeable
region, which may include the entirety of the inner permeable
region. Similar to the discussion of FIGS. 10A and 10B, the
configuration of FIG. 12 may be varied to provide initial blockage
of the inner permeable region 708 that is opened upon satisfaction
of a triggering condition, such as the commencement of production
of a desired fluid.
FIG. 13 schematically presents a variation on the embodiments shown
in FIGS. 7 and 8 wherein the flow control systems are formed using
parts of the wellbore and/or casing to form the outer jacket or
second tubular member. FIG. 13 schematically illustrates the use of
gravel pack or fracture pack techniques in the annulus between the
wellbore wall and the production tubing string, such as including
gravel 756. FIG. 13 illustrates the production fluids 109 within a
production interval 108 adjacent to an open-hole wellbore. The wall
of the open wellbore provides the outer jacket 704 of the present
invention and the region of the wellbore wall adjacent to the
production interval provides the effective outer permeable region
706 through which production fluids pass to reach the external flow
area 716.
As can be seen in FIG. 13, the particulate pack 712 is disposed
adjacent to the production interval such that the fluids entering
the external flow area 716 come into contract with the particulate
pack 712. As illustrated, the particulate pack 712 may be coupled
to the production tubing and/or to the packer 124 serving as the
flow chamber isolator 710. Acceptable configurations of the
particulate pack will depend at least in part on the location of
the production interval relative to the flow control chamber 720
defined by the packers 124. Once the particles are released from
the particulate pack 712, the fluid flow path 732 carries the
particles toward the gravel pack 756. In some implementations, the
gravel pack 756 and released particles may be configured to allow
the released particles through the gravel pack to form a
particulate accumulation at the inner permeable region 708.
Additionally or alternatively, at least some of the released
particles may be retained by the gravel pack 756 and the
particulate accumulation may be formed adjacent to the inner
permeable region 708 but not directly contacting the permeable
region. For example, the particulate accumulation may form at the
top of the gravel pack 756 shown in FIG. 13, which would have
substantially the same impact as a particulate accumulation formed
at the inner permeable region 708.
Flow control systems within the scope of the present invention may
include any of the variations and features discussed herein, which
may include combining and/or rearranging features from one or more
of FIGS. 1-13. As one example of a rearranging of the features
illustrated above, packer technology, such as disclosed in
connection with FIGS. 7 and 8, may be utilized in implementations
where the packers are not serving as the chamber isolators. The
packers would provide zonal isolation in addition to the local flow
control provided by the flow control systems disclosed herein. FIG.
14 provides a relatively high level flow chart of at least some of
the steps involved in implementing or developing flow control
systems of the present invention. To the extent that the steps
outlined in FIG. 14 utilize terminology more closely related to one
or more of the embodiments described above, it should be noted that
the method of FIG. 14 is merely representative of steps that may be
taken according to the present invention as part of methods for
forming or preparing flow control systems within the scope of the
present invention.
In the exemplary method 800 of FIG. 14, the method commences with
providing a base pipe 802 having an inlet to an internal flow
channel. The inlet may be referred to as an inner permeable region.
Additionally, an outer jacket is provided at 804. Similar to the
base pipe, the outer jacket has an inlet, which may be referred to
as an outer permeable region. The outer jacket referred to at step
804 may be any form or configuration of outer jacket, including
those described herein, such as a second tubular member, a casing,
or a wellbore wall. The outer jacket is then disposed at least
partially around the base pipe at 806. The relationship between the
outer jacket and the base pipe defines at least one external flow
area. Accordingly, production fluids entering through the outer
permeable region flow through the external flow area to the inner
permeable region before passing into the internal flow channel.
The method of FIG. 14 continues with the provision of a
consolidated particulate pack at 808, which is then disposed in the
external flow area at 810. The consolidated particulate pack may be
according to any of the various configurations described herein and
variations and equivalents thereof. Additionally, the consolidated
particulate pack may be disposed in the external flow area in any
suitable manner that allows the particulate pack to be touched by
the incoming production fluids en route to the inner permeable
region. A flow control chamber is then defined at 812 to close
portions of the external flow area and control the flow of fluids
and particles released from the particulate pack.
The flow chart of FIG. 14 and/or the description herein of FIG. 14
include text or representations that imply a particular order to
the steps or a timing of the steps. However, any one or more of the
steps of FIG. 14 may be reordered and accomplished with greater or
fewer steps without departing from the present methods. For
example, the outer permeable region of the outer jacket may be
created after the outer jacket is already disposed around the base
pipe. Similarly, one or more elements that are used to define the
flow control chamber may be associated with the base pipe and/or
the outer jacket before the particulate pack is disposed in the
external flow area. As one example, a first packer or chamber
isolator may be installed between the base pipe and the outer
jacket, particulate pack may then be disposed in the external flow
area, and the second packer or chamber isolator may be installed.
Other variations on the steps of FIG. 14 are within the scope of
the present invention.
FIG. 15 similarly provides a representative flow chart of steps
that may be taken in methods of the present invention of utilizing
flow control systems described herein. Similar to FIG. 14, the
steps themselves and the order of the steps described in connection
with FIG. 15 are representative only of some of the methods of the
present invention. Variations in the steps and/or the order of the
steps is within the scope of the present invention when such
variations produce a flow control system utilizing a particulate
material disposed in an external flow area that transitions from a
first fixed condition to a free or released condition without
requiring user or operator intervention when a triggering condition
is satisfied, which released particles return to an accumulated,
fixed condition, again without user or operator intervention, to
control the flow of production fluids through a flow control
chamber.
FIG. 15 illustrates methods 900 of operating flow control systems
of the present invention to control flow through a portion of the
flow control system. Accordingly, the operating methods 900 of FIG.
15 including providing a wellbore environment 902. The operating
methods 900 may further include, at 904, providing a first tubular
member and a second tubular member to define at least partially an
external flow area. The second tubular member may be concentrically
associated with the first tubular member such that the external
flow area is an annulus between the first tubular member and the
second tubular member. Additionally, the external flow area may be
divided into smaller flow areas as appropriate.
Continuing with the methods of FIG. 15, the first tubular member is
provided with an inner permeable region and the second tubular
member is provided with an outer permeable region. The outer and
inner permeable regions together with the external flow area may be
configured to provide a flow path from a source of production
fluids to an internal flow channel of the first tubular member. The
provision of an inner permeable region and an outer permeable
region is illustrated as 906 in FIG. 15, but it should be noted
that the first and second tubular members may be provided with
pre-formed permeable regions thereby rendering this step optional.
Moreover, as indicated in FIG. 15, the relationship between the
first and second tubular members and/or the inner and outer
permeable regions may such that the permeable regions are offset
from each other. In the event that the inner and outer permeable
regions are offset, the flow path from the source of production
fluids to the internal flow channel may be referred to as a changed
flow path and the associated flow control chamber may be referred
to as a changed-path flow control chamber.
Additionally, the methods 900 of FIG. 15 include providing a
consolidated particulate pack and disposing the same in the
external flow area, as indicated at 908. The consolidated
particulate pack may be according to any of the descriptions
provided herein and may be coupled to the first tubular member, the
second tubular member, and/or another member of the flow control
systems. It should also be noted that the consolidated particulate
pack is disposed in the flow path prior to the production fluids
passing through the inner permeable region to the internal flow
channel. Typically, the particulate pack(s) will be disposed
between the outer and the inner permeable regions. The manner in
which the particulate pack(s) are disposed in the external flow
area may be according to any of the configurations described herein
or otherwise that places the particulate pack in a position to be
exposed to the conditions to which the particulate pack is intended
to respond.
At 910, it can be seen that the methods 900 of FIG. 15 include
defining flow control chamber(s). The flow control chambers include
at least one particulate pack and at least a portion of the
external flow area. The materials or elements used to define the
flow control chambers, as described above, may vary depending on
the other design choices for the flow control system and/or the
conditions of the wellbore. For example, the flow control chamber
may be formed between two concentric pipes that are then disposed
in the wellbore environment, such as shown at optional step 912.
Alternatively, the flow control chamber may be formed by the
relationship between a wellbore wall (cased or open), a base pipe
disposed within the wellbore, and packers. As this alternative flow
control chamber illustrates, the step 912 of disposing the flow
control chamber in a wellbore environment is optional because it
may have been accomplished as part of another step in the method
900, such as the step 904 of providing a first and second tubular
member defining an external flow area.
Once the flow control chamber is defined and disposed in the
wellbore environment, the methods allow produced fluids to enter
the flow control chamber, at 914. The fluids may be allowed to
enter the flow control chamber through any of the various methods
used to initiate the flow of production fluids in a wellbore. As
the production fluids enter the external flow area the fluids
contact the particulate pack(s). In the event that the production
fluids satisfy a triggering condition, such as the presence of
water or the presence of water in too great a concentration, the
particulate pack(s) are configured to release at least some of the
particles into the flow within the external flow area, as indicated
at 916. The release of particles is self-regulated and requires no
user or operator intervention. The released particles and the inner
permeable region are configured such that at least some of the
released particles are retained in the external flow area and form,
at 918, a particulate accumulation adjacent to the inner permeable
region. The particulate accumulation then blocks at least a portion
of the inner permeable region to control the flow of fluids
satisfying a predetermined triggering condition.
As can be seen with reference to FIGS. 1-13 and the related
description herein, the variety of configurations within the scope
of the present invention are numerous but joined by common themes.
Similarly, the methods of preparing, implementing, and using the
systems of the present invention are diverse as are the conditions
under which the present systems and methods may be used.
Accordingly, the present flow control systems and methods may be
used in a variety of production intervals or zones and under a
variety of operating conditions. Beneficially, the various
combinations of these flow control systems, such as those
illustrated in FIGS. 2-13, may be utilized to control more than
just the production of water or other undesirable fluid condition.
For example, the implementation of the present invention to control
the flow of water will have the beneficial effect of controlling
the flow of sand that generally accompanies the flow of water.
Additionally or alternatively, the present systems and methods may
provide an operator with the ability to block the flow of
production fluids in one region of a wellbore while at the same
time allowing other production intervals to continue to produce
fluids unimpeded by sand and/or water production from the blocked
production interval. Further, because this mechanism does not have
any moving parts or components, it provides a low cost mechanism to
shut off water production and/or other undesirable flow conditions
for certain oil field applications.
The present techniques also encompass the placement of a composite
particulate pack in a wellbore adjacent to a previously disposed
basepipe. For example, some wells may already have a perforated
basepipe disposed in them to allow production fluid coming into the
well, but lack a reliable, self-regulated way to control the fluid
through the perforated base pipe if the production fluid becomes
undesirable in particular region of the well or interval of the
formation. These wells may not have produced water (or other
condition) at the time the basepipe was originally placed, but have
begun to produce water or are likely to begin producing such
byproducts. In a case such as this, an operator may run a smaller
tubular member inside the base pipe (rendering the original base
pipe an outer jacket according to the language of the present
disclosure) and position a particulate pack in the newly formed
annulus between the original base pipe and the new, smaller tubular
member.
While the present techniques of the invention may be susceptible to
various modifications and alternative forms, the exemplary
embodiments discussed above have been shown by way of example.
However, it should again be understood that the invention is not
intended to be limited to the particular embodiments disclosed
herein. Indeed, the present techniques of the invention are to
cover all modifications, equivalents, and alternatives falling
within the spirit and scope of the invention as defined by the
following appended claims.
* * * * *